Corrosion in High Rate Gas Wells—A Case History

Abstract

Abstract The Reedijk-1 gas well was completed in 1992 with 3 ½" Carbon Steel (CS) tubing and taken into production early 2003 with a capacity of 1.8 mln Nm³/d. Due to the CO2 content, continuous corrosion inhibition was required. However as a result of operational problems it took about 9 months before injection was established. In August 2004 it was observed that the annulus injection pressure increased slowly towards the tubing head pressure and finally became equal. By closing the flapper valve and releasing some pressure of the tubing, it was assessed that the communication should take place above the subsurface safety valve. A downhole video camera run was carried out and identified the leak 1.8 m below the top of the tubing hanger. The camera also revealed that pipe bodies were still in good shape but the couplings showed severe pitting. Subsequently, straddling off the leaking coupling minimized gas production deferment. The well could normally be produced until it was worked over to 5" Chromium 13 (Cr13) tubing. From this case history it can be learned that: In high rate gas wells understanding the film persistency of the chemical corrosion inhibitor is important as removal of inhibitor films is a possibility due to the high velocities thereby leaving this part of the tubing unprotected. This is especially the case at subsurface safety valve (SSSV) depth as a result of the restricted diameter.The application of chemical corrosion inhibition in downhole situations may not manage corrosion when pitting corrosion has been initiated.Alternative solutions to corrosion management need to be sought. Improved technologies that enable increased inhibitor availability, improved inhibitor chemistry's demonstrating high persistency at high gas velocities. Application techniques such a batch dumping of corrosion inhibitor into the well with high persistency chemicals are being tried as alternatives.